1. Technical Field
The inventions generally relate to the field of producing crude oil or natural gas from a well. More particularly, the inventions are directed to improved methods and well fluids for use in wells.
2. Background Art
Oil & Gas Reservoirs
In the context of production from a well, oil and gas (in this context referring to crude oil and natural gas) are well understood to refer to hydrocarbons naturally occurring in certain subterranean formations. A hydrocarbon is a naturally occurring organic compound comprising hydrogen and carbon. A hydrocarbon molecule can range from being as simple as methane (CH4) to a large, highly complex molecule. Petroleum is a mixture of many different hydrocarbons.
A subterranean formation is a body of rock that has sufficiently distinctive characteristics and is sufficiently continuous for geologists to describe, map, and name it. In the context of formation evaluation, the term refers to the volume of rock seen by a measurement made through a wellbore, as in a log or a well test. These measurements indicate the physical properties of this volume of rock, such as the property of permeability.
A subterranean formation containing oil or gas is sometimes referred to as a reservoir. A reservoir is a subsurface, porous, permeable, or naturally fractured rock body in which oil or gas is stored. Most reservoir rocks are limestones, dolomites, sandstones, or a combination of these. The four basic types of hydrocarbon reservoirs are oil, volatile oil, gas condensate, and dry gas.
An oil reservoir generally contains three fluids—gas, oil, and water—with oil the dominant product. In the typical oil reservoir, these fluids become vertically segregated because of their different densities. Gas, the lightest, occupies the upper part of the reservoir rocks; water, the lower part; and oil, the intermediate section. In addition to its occurrence as a cap or in solution, gas may accumulate independently of the oil; if so, the reservoir is called a gas reservoir. Associated with the gas, in most instances, are salt water and some oil.
Volatile oil reservoirs are exceptional in that during early production they are mostly productive of light oil plus gas, but, as depletion occurs, production can become almost completely gas. Volatile oils are usually good candidates for pressure maintenance, which can result in increased reserves.
In a gas condensate reservoir, the hydrocarbons may exist as a gas, but, when brought to the surface, some of the heavier hydrocarbons condense and become a liquid.
In the typical dry gas reservoir natural gas exists only as a gas and production is only gas plus fresh water that condenses from the flow stream reservoir. The conventional natural gas reservoirs have a matrix permeability in the range of about 500 milliDarcy to about 1 milliDarcy.
A reservoir is in a shape that will trap hydrocarbons and that is covered by a relatively impermeable rock, known as cap rock. The cap rock forms a barrier above reservoir rock so that fluids cannot migrate beyond the reservoir. A cap rock capable of being a barrier to fluid migration on a geological time scale has a permeability that is less than about 1 microDarcy. Cap rock is commonly salt, anhydrite, or shale.
A conventional reservoir is a reservoir where the hydrocarbons flow to the wellbore in a manner in which the system can be characterized by flow through permeable media, where the permeability may or may not have been altered near the wellbore, or flow through permeable media to a permeable (conductive), bi-wing fracture placed in the formation. In addition, the hydrocarbons location in the reservoir are held in place by an upper, impermeable barrier and different reservoir fluids are located vertically based on their density where the movement of one of the reservoir fluid can apply a driving force to another reservoir fluid. A convention reservoir would typically have a matrix permeability greater than about 1 milliDarcy (equivalent to about 1,000 microDarcy).
Tight gas, however, is natural gas that is difficult to access because the matrix permeability is relatively low. Generally, tight gas is in a subterranean formation having a matrix permeability in the range of about 1 milliDarcy to about 0.01 milliDarcy (equivalent to about 10 microDarcy). Conventionally, to produce tight gas it is necessary to find a “sweet spot” where a large amount of gas is accessible, and sometimes to use various means to create a reduced pressure in the well to help draw the gas out of the formation.
In addition, shale can include relatively large amounts of organic material compared with other types of rock. Shale is a sedimentary rock derived from mud. Shale rock is commonly finely laminated (bedded). Particles in shale are commonly clay minerals mixed with tiny grains of quartz eroded from pre-existing rocks. Shale is a type of sedimentary rock that contains clay and minerals such as quartz. Gas is very difficult to produce from shale, however, because the matrix permeability of the shale is often less than about 1 microDarcy.
A reservoir may be located under land or under the seabed off shore. Oil and gas reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs) below the surface of the land or seabed.
Producing Oil and Gas
To produce oil or gas from a reservoir, a wellbore is drilled into a subterranean formation, which may be the reservoir or adjacent to the reservoir. A well includes at least one wellbore. The wellbore refers to the drilled hole, including any cased or uncased portions of the well. The borehole usually refers to the inside wellbore wall, that is, the rock face or wall that bounds the drilled hole. A wellbore can have portions that are vertical, horizontal, or anything in between, and it can have portions that are straight, curved, or branched. The wellhead is the surface termination of a wellbore, which surface may be on land or on a seabed. As used herein, “uphole,” “downhole,” and similar terms are relative to the direction of the wellhead, regardless of whether a wellbore portion is vertical or horizontal.
Broadly, a zone refers to an interval of rock along a wellbore that is differentiated from surrounding rocks based on hydrocarbon content or other features, such as perforations or other fluid communication with the wellbore, faults, or fractures. The near-wellbore region of a zone is usually considered to include the matrix of the rock within a few inches of the borehole. As used herein, the near-wellbore region of a zone is considered to be anywhere within about 12 inches of the wellbore. The far-field region of a zone is usually considered the matrix of the rock that is beyond the near-wellbore region.
Generally, well services include a wide variety of operations that may be performed in oil, gas, geothermal, or water wells, such as drilling, cementing, completion, and intervention. These well services are designed to facilitate or enhance the production of desirable fluids from or through a subterranean formation.
Drilling is the process of drilling the wellbore. After the hole is drilled, sections of steel pipe, referred to as casing, which are slightly smaller in diameter than the borehole, are placed in at least the uppermost portions of the wellbore. The casing provides structural integrity to the newly drilled borehole.
Cementing is a common well operation. For example, hydraulic cement compositions can be used in cementing operations in which a string of pipe, such as casing or liner, is cemented in a wellbore. The cemented string of pipe isolates different zones of the wellbore from each other and from the surface. Hydraulic cement compositions can be use in primary cementing of the casing or in completion operations. Hydraulic cement compositions can also be utilized in intervention operations, such as in plugging highly permeable zones or fractures in zones that may be producing too much water, plugging cracks or holes in pipe strings, and the like.
Completion is the process of making a well ready for production or injection. This principally involves preparing a zone of the wellbore to the required specifications, running in the production tubing and associated downhole equipment, as well as perforating and stimulating as required.
Intervention is any operation carried out on a well during or at the end of its productive life that alters the state of the well or well geometry, provides well diagnostics, or manages the production of the well. Workover can broadly refer to any kind of well intervention that involves invasive techniques, such as wireline, coiled tubing, or snubbing. More specifically, though, workover refers to the process of pulling and replacing a completion.
As used herein, a “well fluid” broadly refers to any fluid adapted to be introduced into a well for any well-servicing purpose. A well fluid can be, for example, a drilling fluid, a cementing fluid, a treatment fluid, or a spacer fluid. If a well fluid is to be used in a relatively small volume, for example less than about 200 barrels, it is sometimes referred to in the art as a wash, dump, slug, or pill.
As used herein, “into a well” means introduced at least into and through the wellhead. According to various techniques known in the art, equipment, tools, or well fluids can be directed from the wellhead into any desired portion of the wellbore. Additionally, a well fluid can be directed from a portion of the wellbore into the rock matrix of a zone.
Drilling and Drilling Fluids
The well is created by drilling a hole into the earth (or seabed) with a drilling rig that rotates a drill string with a drilling bit attached to the downward end. Usually the borehole is anywhere between about 5 inches (13 cm) to about 36 inches (91 cm) in diameter. The borehole usually is stepped down to a smaller diameter the deeper the wellbore as upper portions are cased or lined, which means that progressively smaller drilling strings and bits must be used to pass through the uphole casing or liner.
While drilling an oil or gas well, a drilling fluid is circulated downhole through a drillpipe to a drill bit at the downhole end, out through the drill bit into the wellbore, and then back uphole to the surface through the annular path between the tubular drillpipe and the borehole. The purpose of the drilling fluid is to maintain hydrostatic pressure in the wellbore, to lubricate the drill string, and to carry rock cuttings out from the wellbore.
The drilling fluid can be water-based or oil-based. Oil-based fluids tend to have better lubricating properties than water-based fluids, nevertheless, other factors can mitigate in favor of using a water-based drilling fluid.
In addition, the drilling fluid may be viscosified to help suspend and carry rock cuttings out from the wellbore. Rock cuttings can range in size from silt-sized particles to chunks measured in centimeters. Carrying capacity refers to the ability of a circulating drilling fluid to transport rock cuttings out of a wellbore. Other terms for carrying capacity include hole-cleaning capacity and cuttings lifting.
Cementing and Hydraulic Cement Compositions
In performing cementing, a hydraulic cement composition is pumped as a fluid (typically in the form of suspension or slurry) into a desired location in the wellbore. For example, in cementing a casing or liner, the hydraulic cement composition is pumped into the annular space between the exterior surfaces of a pipe string and the borehole (that is, the wall of the wellbore). The cement composition is allowed time to set in the annular space, thereby forming an annular sheath of hardened, substantially impermeable cement. The hardened cement supports and positions the pipe string in the wellbore and bonds the exterior surfaces of the pipe string to the walls of the wellbore.
Hydraulic cement is a material that when mixed with water hardens or sets over time because of a chemical reaction with the water. Because this is a chemical reaction with the water, hydraulic cement is capable of setting even under water. The hydraulic cement, water, and any other components are mixed to form a hydraulic cement composition in the initial state of a slurry, which should be a fluid for a sufficient time before setting for pumping the composition into the wellbore and for placement in a desired downhole location in the well.
Well Treatments and Treatment Fluids
Drilling, completion, and intervention operations can include various types of treatments that are commonly performed in a wellbore or subterranean formation. For example, a treatment for fluid-loss control can be used during any of drilling, completion, and intervention operations. During completion or intervention, stimulation is a type of treatment performed to enhance or restore the productivity of oil and gas from a well. Stimulation treatments fall into two main groups: hydraulic fracturing and matrix treatments. Fracturing treatments are performed above the fracture pressure of the subterranean formation to create or extend a highly permeable flow path between the formation and the wellbore. Matrix treatments are performed below the fracture pressure of the formation. Other types of completion or intervention treatments can include, for example, gravel packing, consolidation, and controlling excessive water production.
As used herein, the word “treatment” refers to any treatment for changing a condition of a wellbore or an adjacent subterranean formation. Examples of treatments include fluid-loss control, isolation, stimulation, or conformance control; however, the word “treatment” does not necessarily imply any particular treatment purpose.
A treatment usually involves introducing a treatment fluid into a well. As used herein, a “treatment fluid” is a fluid used in a treatment. Unless the context otherwise requires, the word “treatment” in the term “treatment fluid” does not necessarily imply any particular treatment or action by the fluid. If a treatment fluid is to be used in a relatively small volume, for example less than about 200 barrels, it is sometimes referred to in the art as a slug or pill.
As used herein, a “treatment zone” refers to an interval of rock along a wellbore into which a treatment fluid is directed to flow from the wellbore. Further, as used herein, “into a treatment zone” means into and through the wellhead and, additionally, through the wellbore and into the treatment zone.
The following are some general descriptions of common well treatments and associated treatment fluids. Of course, other well treatments and treatment fluids are known in the art.
Well Treatment—Fluid-Loss Control
Fluid loss refers to the undesirable leakage of a fluid phase of a well fluid into the permeable matrix of a zone, which zone may or may not be a treatment zone. Fluid-loss control refers to treatments designed to reduce such undesirable leakage. Providing effective fluid-loss control for well fluids during certain stages of well operations is usually highly desirable.
The usual approach to fluid-loss control is to substantially reduce the permeability of the matrix of the zone with a fluid-loss control material that blocks the permeability at or near the face of the rock matrix of the zone. For example, the fluid-loss control material may be a particulate that has a size selected to bridge and plug the pore throats of the matrix. All else being equal, the higher the concentration of the particulate, the faster bridging will occur. As the fluid phase carrying the fluid-loss control material leaks into the formation, the fluid-loss control material bridges the pore throats of the matrix of the formation and builds up on the surface of the borehole or fracture face or penetrates only a little into the matrix. The buildup of solid particulate or other fluid-loss control material on the walls of a wellbore or a fracture is referred to as a filter cake. Depending on the nature of a fluid phase and the filter cake, such a filter cake may help block the further loss of a fluid phase (referred to as a filtrate) into the subterranean formation. A fluid-loss control material is specifically designed to lower the volume of a filtrate that passes through a filter medium.
After application of a filter cake, however, it may be desirable to restore permeability into the formation. If the formation permeability of the desired producing zone is not restored, production levels from the formation can be significantly lower. Any filter cake or any solid or polymer filtration into the matrix of the zone resulting from a fluid-loss control treatment must be removed to restore the formation's permeability, preferably to at least its original level. This is often referred to as clean up.
A variety of fluid-loss control materials have been used and evaluated for fluid-loss control and clean-up, including foams, oil-soluble resins, acid-soluble solid particulates, graded salt slurries, linear viscoelastic polymers, and heavy metal-crosslinked polymers. Their respective comparative effects are well documented.
Fluid-loss control materials are sometimes used in drilling fluids or in treatments that have been developed to control fluid loss. A fluid-loss control pill is a treatment fluid that is designed or used to provide some degree of fluid-loss control. Through a combination of viscosity, solids bridging, and cake buildup on the porous rock, these pills oftentimes are able to substantially reduce the permeability of a zone of the subterranean formation to fluid loss. They also generally enhance filter-cake buildup on the face of the formation to inhibit fluid flow into the formation from the wellbore.
Fluid-loss control pills typically comprise an aqueous base fluid and a high concentration of a gelling agent polymer (usually crosslinked), and sometimes, bridging particles, like graded sand, graded salt particulate, or sized calcium carbonate particulate. A commonly used fluid-loss control pills contain high concentrations (100 to 150 lbs/1000 gal) of derivatized hydroxyethylcellulose (“HEC”). HEC is generally accepted as a gelling agent affording minimal permeability damage during completion operations. Normally, HEC polymer solutions do not form rigid gels, but control fluid loss by a viscosity-regulated or filtration mechanism. Some other gelling agent polymers that have been used include xanthan, guar, guar derivatives, carboxymethylhydroxyethylcellulose (“CMHEC”), and starch. Viscoelastic surfactants can also be used.
As an alternative to forming linear polymeric gels for fluid-loss control, crosslinked gels often are used. Crosslinking the gelling agent polymer creates a gel structure that can support solids as well as provide fluid-loss control. Further, crosslinked fluid-loss control pills have demonstrated that they require relatively limited invasion of the formation face to be fully effective. To crosslink the gelling agent polymers, a suitable crosslinking agent that comprises polyvalent metal ions is used. Aluminum, titanium, and zirconium are common examples.
A preferred crosslinkable gelling agent for fluid-loss control pills are graft copolymers of a hydroxyalkyl cellulose, guar, or hydroxypropyl guar that are prepared by a redox reaction with vinyl phosphonic acid. The gel is formed by hydrating the graft copolymer in an aqueous solution containing at least a trace amount of at least one divalent cation. The gel is crosslinked by the addition of a Lewis base or Bronsted-Lowrey base so that pH of the aqueous solution is adjusted from slightly acidic to slightly basic. Preferably, the chosen base is substantially free of polyvalent metal ions. The resulting crosslinked gel demonstrates shear-thinning and rehealing properties that provide relatively easy pumping, while the rehealed gel provides good fluid-loss control upon placement. This gel can be broken by reducing the pH of the fluid or by the use of oxidizers. Some fluid-loss pills of this type are described in U.S. Pat. No. 5,304,620, assigned to Halliburton Energy Services, the relevant disclosure of which is incorporated herein by reference. Fluid-loss control pills of this type are commercially available under the trade name “K-MAX” from Halliburton Energy Services Inc. in Duncan, Okla.
Well Treatment—Acidizing
A widely used stimulation technique is acidizing, in which a treatment fluid including an aqueous acid solution is introduced into the formation to dissolve acid-soluble materials. In this way, hydrocarbon fluids can more easily flow from the formation into the well. In addition, an acid treatment can facilitate the flow of injected treatment fluids from the well into the formation.
Acidizing techniques can be carried out as matrix acidizing procedures or as acid fracturing procedures.
In matrix acidizing, an acidizing fluid is injected from the well into the formation at a rate and pressure below the pressure sufficient to create a fracture in the formation. In sandstone formations, the acid primarily removes or dissolves acid soluble damage in the near wellbore region and is thus classically considered a damage removal technique and not a stimulation technique. In carbonate formations, the goal is to actually a stimulation treatment where in the acid forms conducted channels called wormholes in the formation rock. Greater details, methodology, and exceptions can be found in “Production Enhancement with Acid Stimulation” 2nd edition by Leonard Kalfayan (PennWell 2008), SPE 129329, SPE 123869, SPE 121464, SPE 121803, SPE 121008, IPTC 10693, 66564-PA, and the references contained therein.
In acid fracturing, an acidizing fluid is pumped into a carbonate formation at a sufficient pressure to cause fracturing of the formation and creating differential (non-uniform) etching fracture conductivity. Greater details, methodology, and exceptions can be found in “Production Enhancement with Acid Stimulation” 2nd edition by Leonard Kalfayan (PennWell 2008), SPE 129329, SPE 123869, SPE 121464, SPE 121803, SPE 121008, IPTC 10693, 66564-PA, and the references contained therein.
Matrix Diversion
Matrix treatments in conventional reservoirs can utilize diversion. True matrix diversion does not apply, however, to ultra-low permeable formations.
For example, in subterranean treatments in conventional reservoirs, it is often desired to treat an interval of a subterranean formation having sections of varying permeability, reservoir pressures and/or varying degrees of formation damage, and thus may accept varying amounts of certain treatment fluids. For example, low reservoir pressure in certain areas of a subterranean formation or a rock matrix or a proppant pack of high permeability may permit that portion to accept larger amounts of certain treatment fluids. It may be difficult to obtain a uniform distribution of the treatment fluid throughout the entire interval. For instance, the treatment fluid may preferentially enter portions of the interval with low fluid flow resistance at the expense of portions of the interval with higher fluid flow resistance. In some instances, these intervals with variable flow resistance may be water-producing intervals. This is different from diversion between different zones. See U.S. application Ser. No. 12/512,232, filed Jul. 30, 2009, entitled “Methods of Fluid Loss Control and Fluid Diversion in Subterranean Formations,” which is incorporated by reference.
In addition, relative permeability modifiers (RPMs) can be considered another approach to matrix diversion.
Well Treatment—Hydraulic Fracturing
Hydraulic fracturing, sometimes referred to as fracturing or fracing, is a common stimulation treatment. A treatment fluid adapted for this purpose is sometimes referred to as a fracturing fluid. The fracturing fluid is pumped at a sufficiently high flow rate and pressure into the wellbore and into the subterranean formation to create or enhance a fracture in the subterranean formation. Creating a fracture means making a new fracture in the formation. Enhancing a fracture means enlarging a pre-existing fracture in the formation.
A frac pump is used for hydraulic fracturing. A frac pump is a high-pressure, high-volume pump. Typically, a frac pump is a positive-displacement reciprocating pump. The structure of such a pump is resistant to the effects of pumping abrasive fluids, and the pump is constructed of materials that are resistant to the effects of pumping corrosive fluids. Abrasive fluids are suspensions of hard, solid particulates, such as sand. Corrosive fluids include, for example, acids. The fracturing fluid may be pumped down into the wellbore at high rates and pressures, for example, at a flow rate in excess of 50 barrels per minute (2,100 U.S. gallons per minute) at a pressure in excess of 5,000 pounds per square inch (“psi”). The pump rate and pressure of the fracturing fluid may be even higher, for example, flow rates in excess of 100 barrels per minute and pressures in excess of 10,000 psi are common.
Fracturing a subterranean formation often uses hundreds of thousands of gallons of fracturing fluid or more. Further, it is often desirable to fracture more than one treatment zone of a well. Thus, a high volume of fracturing fluids is often used in fracturing of a well, which means that a low-cost fracturing fluid is desirable. Because of the ready availability and relative low cost of water compared to other liquids, among other considerations, a fracturing fluid is usually water-based.
The creation or extension of a fracture in hydraulic fracturing occurs suddenly. When this happens, the fracturing fluid suddenly has a fluid flow path through the fracture to flow more rapidly away from the wellbore, which may be detected as a change in pressure or fluid flow rate.
A newly-created or newly-extended fracture will tend to close together after the pumping of the fracturing fluid is stopped. To prevent the fracture from closing, a material is usually placed in the fracture to keep the fracture propped open and to provide higher fluid conductivity than the matrix of the formation. A material used for this purpose is referred to as a proppant.
A proppant is in the form of a solid particulate, which can be suspended in the fracturing fluid, carried downhole, and deposited in the fracture to form a proppant pack. The proppant pack props the fracture in an open condition while allowing fluid flow through the permeability of the pack. The proppant pack in the fracture provides a higher-permeability flow path for the oil or gas to reach the wellbore compared to the permeability of the matrix of the surrounding subterranean formation. This higher-permeability flow path increases oil and gas production from the subterranean formation.
A particulate for use as a proppant is usually selected based on the characteristics of size range, crush strength, and solid stability in the types of fluids that are encountered or used in wells. Preferably, a proppant should not melt, dissolve, or otherwise degrade from the solid state under the downhole conditions.
The proppant is selected to be an appropriate size to prop open the fracture and bridge the fracture width expected to be created by the fracturing conditions and the fracturing fluid. If the proppant is too large, it will not easily pass into a fracture and will screenout too early. If the proppant is too small, it will not provide the fluid conductivity to enhance production. See, for example, McGuire and Sikora, 1960. In the case of fracturing relatively permeable or even tight-gas reservoirs, a proppant pack should provide higher permeability than the matrix of the formation. In the case of fracturing ultra-low permeable formations, such as shale formations, a proppant pack should provide for higher permeability than the naturally occurring fractures or other micro-fractures of the fracture complexity.
Appropriate sizes of particulate for use as a proppant are typically in the range from about 8 to about 100 U.S. Standard Mesh. A typical proppant is sand-sized, which geologically is defined as having a largest dimension ranging from about 0.06 millimeters up to about 2 millimeters (mm). (The next smaller particle size class below sand sized is silt, which is defined as having a largest dimension ranging from less than about 0.06 mm down to about 0.004 mm.) As used herein, proppant does not mean or refer to suspended solids, silt, fines, or other types of insoluble solid particulate smaller than about 0.06 mm (about 230 U.S. Standard Mesh). Further, it does not mean or refer to particulates larger than about 3 mm (about 7 U.S. Standard Mesh).
The proppant is sufficiently strong, that is, has a sufficient compressive or crush resistance, to prop the fracture open without being deformed or crushed by the closure stress of the fracture in the subterranean formation. For example, for a proppant material that crushes under closure stress, a 20/40 mesh proppant preferably has an API crush strength of at least 4,000 psi closure stress based on 10% crush fines according to procedure API RP-56, A 12/20 mesh proppant material preferably has an API crush strength of at least 4,000 psi closure stress based on 16% crush fines according to procedure API RP-56. This performance is that of a medium crush-strength proppant, whereas a very high crush-strength proppant would have a crush-strength of about 10,000 psi. In comparison, for example, a 100-mesh proppant material for use in an ultra-low permeable formation such as shale preferably has an API crush strength of at least 5,000 psi closure stress based on 6% crush fines. The higher the closing pressure of the formation of the fracturing application, the higher the strength of proppant is needed. The closure stress depends on a number of factors known in the art, including the depth of the formation.
Further, a suitable proppant should be stable over time and not dissolve in fluids commonly encountered in a well environment. Preferably, a proppant material is selected that will not dissolve in water or crude oil.
Suitable proppant materials include, but are not limited to, sand (silica), ground nut shells or fruit pits, sintered bauxite, glass, plastics, ceramic materials, processed wood, resin coated sand or ground nut shells or fruit pits or other composites, and any combination of the foregoing. Mixtures of different kinds or sizes of proppant can be used as well. In conventional reservoirs, if sand is used, it commonly has a median size anywhere within the range of about 20 to about 100 U.S. Standard Mesh. For a synthetic proppant, it commonly has a median size anywhere within the range of about 8 to about 100 U.S. Standard Mesh.
The concentration of proppant in the treatment fluid depends on the nature of the subterranean formation. As the nature of subterranean formations differs widely, the concentration of proppant in the treatment fluid may be in the range of from about 0.03 kilograms to about 12 kilograms of proppant per liter of liquid phase (from about 0.1 lb/gal to about 25 lb/gal).
Tip Screenout in Fracturing Permeable Formations
The conductivity of propped fractures depends on, among other things, fracture width and fracture permeability. The permeability can be estimated based on the size of the proppant. The width of a fracture depends on the nature of the formation and the specific fracturing conditions.
In relatively permeable formations, it is often desirable to maximize the length of the fractures created by hydraulic fracturing treatments, so that the surface area of the fractures, and therefore the area serviced by the well, may be maximized. In certain frac-packing treatments, particularly in weakly-consolidated highly-permeable sand formations, it may be more desirable to form short, wide fractures that feature high fracture conductivities.
One way of creating such short, wide fractures is with a tip screenout. In a tip screenout, the growth of the fracture length is arrested when the proppant concentration at the tip of the fracture becomes highly concentrated, typically due to fluid leak-off into the surrounding formation. In a fracture tip screenout, the proppant bridges the narrow gaps at the tip of the fracture and are packed into the fracture, thus restricting flow to the fracture tip, which may terminate the extension of the fracture into the formation, among other things, because the hydraulic pressure of the stimulation fluid may not be transmitted from the wellbore to the fracture tip. The concentrated proppant slurry plugs the fracture and prevents additional lengthening of the fracture. Any additional pumping of the proppant slurry beyond this point causes the fracture to widen or balloon and packs the existing fracture length with additional proppant. This results in a relatively short, wide fracture having both high fracture conductivity and a high proppant concentration.
Being able to control the initiation of a fracture tip screenout may be an important aspect of a successful fracturing operation. Without control of the fracture tip screenout, a fracture may not be packed with proppant as needed, e.g., to have the desired fracture width near the wellbore.
Conventionally, to initiate a fracture tip screenout, the flow rate of the fracturing fluid is reduced while increasing proppant concentration therein, with the anticipation that this combination will cause a fracture tip screenout. Design features typically employed in situations in which a tip screenout is desired often involve methods of ensuring that fluid leak-off is high relative to the rate and amount of proppant injection. This can be achieved in a number of ways, including, but not limited to, using a small amount of pad fluid to initiate the fracture, using little or no fluid loss additive, using high proppant concentrations earlier in the treatment, pumping more slowly during the fracturing operation, or some combination thereof. However, this methodology does not consistently cause fracture tip screenouts. While increasing the proppant concentration and decreasing the flow rate does increase the probability that a fracture tip screenout may occur, this methodology assumes that there is one fracture taking all of the fluid. But, where there are competing fractures, the initiation of a fracture tip screenout may be difficult to control and/or predict using conventional methodologies. Pressure transients collected by downhole pressure gauges during frac-packing treatments indicate that tip screenouts often do not occur when and where desired or intended. Instead, the fluid at the tip of the fracture often remains mobile, the fracture tip continues to grow throughout the treatment, and the desired proppant concentration in the fracture is not reached. Because of this, the desired high fracture conductivity may not be obtained.
For example, in deviated wellbores, where only a portion of the perforations communicate with the dominant fracture that is being extended (when using conventional technologies), fluid is lost (e.g., leaking off) into other portions or fractures in the well besides the dominant fracture. Dependent upon the rate of fluid loss into the formation, these conventional methodologies may not successfully generate a tip screenout in the fracture.
Furthermore, the conventional methods cannot predict when the screenout occurs, and, therefore, while it is desirable for the proppant to bridge at the tip of the fracture and pack therein, the bridging of the proppant and thus the screenout may occur anywhere in the fracture. Oftentimes, this may happen near the wellbore, before the high concentration proppant reaches the fracture, causing an undesirable screenout inside the well bore. If the screenout does not occur at the tip, and the fracture is not gradually filled with proppant afterwards, the fracture may not be packed with proppant as desired.
One method of inducing and controlling tip screenout includes pumping an annulus fluid into an annulus, between the subterranean formation and a work string disposed within a wellbore penetrating the subterranean formation, at an annulus flow rate; and reducing the annulus flow rate below a fracture initiation flow point so that the fracture tip screenout is initiated in the one or more fractures in the subterranean formation. U.S. Pat. No. 7,237,612, issued Jul. 3, 2007, titled “Methods of Initiating a fracture Tip Screenout” having for named inventors Jim B. Surjaatmadja, Billy W. McDaniel, Mark Farabee, David Adams, and Loyd East, which is incorporated by reference.
Another method of inducing and controlling tip screenout during a frac-packing treatment comprising injecting a proppant slurry into a subterranean formation, wherein the proppant slurry comprises a proppant material, a fracturing fluid, and degradable particulates and wherein the degradable particulates physically interact with themselves and with the proppant material to aid in inducing tip screenout. U.S. Pat. No. 7,413,017, issued Aug. 19, 2008, titled “Methods and Compositions for Inducing Tip-Screenouts in Frac-Packing Operations” having for named inventors Philip D. Nguyen and Anne M. Culotta, which is incorporated by reference.
Tip screenout requires considerable fluid loss while at fracturing rates. This necessitates a high permeability formation and cannot occur in low permeability formations that have a matrix permeability less than 1,000 microDarcy (equivalent to 1 milliDarcy), much less in ultra-low permeable formations that have a matrix permeability less than 1 microDarcy (equivalent to 0.001 milliDarcy).
Well Treatment—Staged Fracturing and Zone Diversion
Multiple or staged fracturing involves fracturing two or more different zones of a wellbore in succession. Staged hydraulic fracturing operations are commonly performed from horizontal wellbores placed in shale gas reservoirs.
In the context of staged fracturing, diversion techniques are used to divert a fracturing fluid from one zone to a different zone. Diversion techniques fall into two main categories: mechanical diversion and chemical diversion. Mechanical diversion includes the use of mechanical devices, such as ball sealers or packers, to isolate one zone from another and divert a treatment fluid to the desired zone. Chemical diversion includes the use of chemicals to divert a treatment fluid from entering a zone in favor of entering a different zone.
In conventional methods of treating subterranean formations, once the less fluid flow-resistant zone of a subterranean formation has been treated, that zone may be sealed off using a variety of techniques to divert treatment fluids to a more fluid flow-resistant zone of the well. Such techniques may have involved, among other things, the injection of particulates, foams, emulsions, plugs, packers, or blocking polymers (e.g., crosslinked aqueous gels) into the interval so as to plug off high-permeability portions of the subterranean formation once they have been treated, thereby diverting subsequently injected fluids to more fluid flow-resistant portions of the subterranean formation.
For example, near wellbore diversion is a near-wellbore treatment that causes a zone to greatly reduce or stop the taking of fluid so that the fluid is then diverted to enter another zone. This can be accomplished, for example, by plugging wellbore perforations or plugging a near-wellbore proppant pack. According to some techniques known in the art, diversion from one zone to another can be accomplished without stopping the pumping of one or more fracturing fluids into the well.
A fracturing stage includes pumping one or more fracturing fluids into the treatment zone at a rate and pressure above the fracture pressure of the treatment zone. Designing a fracturing stage usually includes determining a designed total pumping time for the stage or determining a designed total pumping volume of fracturing fluid for the fracturing stage. The tail end of a fracturing stage is the last portion of pumping time into the zone or the last portion of the volume of fracturing fluid pumped into the zone. This is usually about the last minute of total pumping time or about the last wellbore volume of a fracturing fluid to be pumped into the zone. The portion of pumping time or fracturing fluid volume that is pumped before the tail end of a fracturing stage reaches into a far-field region of the zone.
A person of skill in the art is able to plan each fracturing stage in detail, subject to unexpected or undesired early screenout or other problems that might be encountered in fracturing a well. A person of skill in the art is able to determine the wellbore volume between the wellhead and the zone. In addition, a person of skill in the art is able to determine the time within a few seconds in which a well fluid pumped into a well should take to reach a zone.
In addition to being designed in advance, the actual point at which a fracturing fluid is diverted from a zone can be determined by a person of skill in the art, including based on observed changes in well pressures or flow rates.
Well Treatment—Gravel Packing
A solid particulate also can be used for gravel packing operations. Gravel packing is commonly used as a sand-control method to prevent production of formation sand from a poorly consolidated subterranean formation. In gravel packing, a mechanical screen is placed in the wellbore and the surrounding annulus packed with a particulate of a specific size designed to prevent the passage of formation sand. The primary objective is to stabilize the formation while causing minimal impairment to well productivity.
The particulate used for this purpose is referred to as “gravel.” In the oil and gas field, and as used herein, the term “gravel” is refers to relatively large particles in the sand size classification, that is, particles ranging in diameter from about 0.1 mm up to about 2 mm. Generally, a particulate having the properties, including chemical stability, of a low-strength proppant is used in gravel packing. An example of a commonly used gravel packing material is sand.
A screenout is a condition encountered during some gravel-pack operations wherein the treatment area cannot accept further packing gravel (larger sand). Under ideal conditions, this should signify that the entire void area has been successfully packed with the gravel. However, if screenout occurs earlier than expected in the treatment, it may indicate an incomplete treatment and the presence of undesirable voids within the treatment zone.
Increasing Viscosity of Fluid for Suspending Particulate
Various particulates can be employed in a fluid for use in a well or a fluid can be used to help remove particulates from a well.
For example, during drilling, rock cuttings should be carried by the drilling fluid and flowed out of the wellbore. The rock cuttings typically have specific gravity greater than 2, which is much higher than that of many drilling fluids.
Similarly, a proppant used in fracturing may have a much different density than the fracturing fluid. For example, sand has a specific gravity of about 2.7, where water has a specific gravity of 1.0 at Standard Laboratory conditions of temperature and pressure. A proppant having a different density than water will tend to separate from water very rapidly.
As many well fluids are water-based, partly for the purpose of helping to suspend particulate of higher density, and for other reasons known in the art, the density of the fluid used in a well can be increased by included highly water-soluble salts in the water, such as potassium chloride. However, increasing the density of a well fluid will rarely be sufficient to match the density of the particulate.
Increasing the viscosity of a well fluid can help prevent a particulate having a different specific gravity than an external phase of the fluid from quickly separating out of the external phase.
Emulsion for Increasing Viscosity
The internal-phase droplets of an emulsion disrupt streamlines and require more effort to get the same flow rate. Thus, an emulsion tends to have a higher viscosity than the external phase of the emulsion would otherwise have by itself. This property of an emulsion can be used to help suspend a particulate material in an emulsion. This technique for increasing the viscosity of a liquid can be used separately or in combination with other techniques for increasing the viscosity of a fluid.
As used herein, to “break” an emulsion means to cause the creaming and coalescence of emulsified drops of the internal dispersed phase so that they the internal phase separates out of the external phase. Breaking an emulsion can be accomplished mechanically (for example, in settlers, cyclones, or centrifuges) or with chemical additives to increase the surface tension of the internal droplets.
Viscosity-Increasing Agent
A viscosity-increasing agent is sometimes referred to in the art as a thickener, gelling agent, or suspending agent. There are several kinds of viscosity-increasing agents and related techniques for increasing the viscosity of a fluid.
In general, because of the high volume of fracturing fluid typically used in a fracturing operation, it is desirable to efficiently increase the viscosity of fracturing fluids to the desired viscosity using as little viscosity-increasing agent as possible. In addition, relatively inexpensive materials are preferred. Being able to use only a small concentration of the viscosity-increasing agent requires a lesser amount of the viscosity-increasing agent in order to achieve the desired fluid viscosity in a large volume of fracturing fluid.
Polymers for Increasing Viscosity
Certain kinds of polymers can be used to increase the viscosity of a fluid. In general, the purpose of using a polymer is to increase the ability of the fluid to suspend and carry a particulate material. Polymers for increasing the viscosity of a fluid are preferably soluble in the external phase of a fluid. Polymers for increasing the viscosity of a fluid can be naturally occurring polymers such as polysaccharides, derivatives of naturally occurring polymers, or synthetic polymers.
Water-Soluble Polysaccharides or Derivatives for Increasing Viscosity
Fracturing fluids are usually water-based. Efficient and inexpensive viscosity-increasing agents for water include certain classes of water-soluble polymers.
Water-soluble polysaccharides are often used to the extent of at least 10 mg per liter in water at 25° C. More preferably, the water-soluble polymer is also used to the extent of at least 10 mg per liter in an aqueous sodium chloride solution of 32 grams sodium chloride per liter of water at 25° C. As will be appreciated by a person of skill in the art, the solubility or dispersability in water of a certain kind of polymeric material may be dependent on the salinity or pH of the water. Accordingly, the salinity or pH of the water can be modified to facilitate the solubility or dispersability of the water-soluble polymer. In some cases, the water-soluble polymer can be mixed with a surfactant to facilitate its solubility in the water or salt solution utilized.
The water-soluble polymer can have an average molecular weight in the range of from about 50,000 to 20,000,000, most preferably from about 100,000 to about 3,000,000.
Typical water-soluble polymers used in well treatments are water-soluble polysaccharides and water-soluble synthetic polymers (e.g., polyacrylamide). The most common water-soluble polysaccharide employed in well treatments is guar and its derivatives.
A polysaccharide can be classified as being non-helical or helical (or random coil type) based on its solution structure in aqueous liquid media. Examples of non-helical polysaccharides include guar, guar derivatives, and cellulose derivatives. Examples of helical polysaccharides include xanthan, diutan, and scleroglucan, and derivatives of any of these.
As used herein, a “polysaccharide” can broadly include a modified or derivative polysaccharide. As used herein, “modified” or “derivative” means a compound or substance formed by a chemical process from a parent compound or substance, wherein the chemical skeleton of the parent exists in the derivative. The chemical process preferably includes at most a few chemical reaction steps, and more preferably only one or two chemical reaction steps. As used herein, a “chemical reaction step” is a chemical reaction between two chemical reactant species to produce at least one chemically different species from the reactants (regardless of the number of transient chemical species that may be formed during the reaction). An example of a chemical step is a substitution reaction. Substitution on a polymeric material may be partial or complete.
A guar derivative can be selected from the group consisting of, for example, a carboxyalkyl derivative of guar, a hydroxyalkyl derivative of guar, and any combination thereof. Preferably, the guar derivative is selected from the group consisting of carboxymethylguar, carboxymethylhydroxyethylguar, hydroxyethylguar, carboxymethylhydroxypropylguar, ethylcarboxymethylguar, and hydroxypropylmethylguar.
A cellulose derivative can be selected from the group consisting of, for example, a carboxyalkyl derivative of cellulose, a hydroxyalkyl derivative of cellulose, and any combination thereof. Preferably, the cellulose derivative is selected from the group consisting of carboxymethylcellulose, carboxymethylhydroxyethylcellulose, hydroxyethylcellulose, methylcellulose, ethylcellulose, ethylcarboxymethylcellulose, and hydroxypropylmethylcellulose.
Crosslinking of Polysaccharide to Increase Viscosity of a Fluid or Form a Gel
The viscosity of a fluid at a given concentration of viscosity-increasing agent can be greatly increased by crosslinking the viscosity-increasing agent. A crosslinking agent, sometimes referred to as a crosslinker, can be used for this purpose. One example of a crosslinking agent is the borate ion. If a polysaccharide is crosslinked to a sufficient extent, it can form a gel with water. Gel formation is based on a number of factors including the particular polymer and concentration thereof, the particular crosslinker and concentration thereof, the degree of crosslinking, temperature, and a variety of other factors known to those of ordinary skill in the art.
A base gel is a fluid that includes a viscosity-increasing agent, such as guar, but that excludes crosslinking agents. Typically, a base gel is a fluid that is mixed with another fluid containing a crosslinker, wherein the mixed fluid is adapted to form a gel after injection downhole at a desired time in a well treatment. A base gel can be used, for example, as the external phase of an emulsion.
Breaker for Polysaccharide or Crosslinked Polysaccharide
Drilling or treatment fluids also commonly include a breaker for a polysaccharide or crosslinked polysaccharide. In this context of viscosity increase provided by a use of a polysaccharide, the term break or breaker as used herein refers to a reduction in the viscosity of a fluid or gel by some breaking of the polymer backbones or some breaking or reversing of the crosslinks between polymer molecules. No particular mechanism is necessarily implied by the term. A breaker for this purpose can be, for example, an acid, a base, an oxidizer, an enzyme, a chelating agent for a metal crosslinker, an azo compound, or a combination of these. The acids, oxidizers, or enzymes can be in the form of delayed-release or encapsulated breakers.
Examples of such suitable breakers for treatment fluids of the present invention include, but are not limited to, sodium chlorites, hypochlorites, perborate, persulfates, and peroxides (including organic peroxides). Other suitable breakers include, but are not limited to, suitable acids and peroxide breakers, delinkers, as well as enzymes that may be effective in breaking viscosified treatment fluids. In some preferred embodiments, the breaker may be citric acid, tetrasodium EDTA, ammonium persulfate, or cellulose enzymes. A breaker may be included in a treatment fluid of the present invention in an amount and form sufficient to achieve the desired viscosity reduction at a desired time. The breaker may be formulated to provide a delayed break, if desired. For example, a suitable breaker may be encapsulated if desired. Suitable encapsulation methods are known to those skilled in the art. One suitable encapsulation method involves coating the selected breaker in a porous material that allows for release of the breaker at a controlled rate. Another suitable encapsulation method that may be used involves coating the chosen breakers with a material that will degrade when downhole so as to release the breaker when desired. Resins that may be suitable include, but are not limited to, polymeric materials that will degrade when downhole.
A treatment fluid can optionally comprise an activator or a retarder to, among other things, optimize the break rate provided by a breaker. Any known activator or retarder that is compatible with the particular breaker used is suitable for use in the present invention. Examples of such suitable activators include, but are not limited to, acid generating materials, chelated iron, copper, cobalt, and reducing sugars. Examples of suitable retarders include sodium thiosulfate, methanol, and diethylenetriamine.
In the case of a crosslinked viscosity-increasing agent, for example, one way to diminish the viscosity is by breaking the crosslinks. For example, the borate crosslinks in a borate-crosslinked gel can be broken by lowering the pH of the fluid. At a pH above 8, the borate ion exists and is available to crosslink and cause gelling. At a lower pH, the borate ion reacts with proton and is not available for crosslinking, thus, an increase in viscosity due to borate crosslinking is reversible.
Viscosifying Surfactants (i.e. Viscoelastic Surfactants)
It should be understood that merely increasing the viscosity of a fluid may only slow the settling or separation of distinct phases and does not necessarily gel the fluid.
Certain viscosity-increasing agents can also help suspend a particulate material by increasing the elastic modulus of the fluid. The elastic modulus is the measure of a substance's tendency to be deformed non-permanently when a force is applied to it. The elastic modulus of a fluid, commonly referred to as G′, is a mathematical expression and defined as the slope of a stress versus strain curve in the elastic deformation region. G′ is expressed in units of pressure, for example, Pa (Pascals) or dynes/cm2. As a point of reference, the elastic modulus of water is negligible and considered to be zero. An example of a viscosity-increasing agent that also increases the elastic modulus of a fluid is a viscoelastic surfactant.
An example of a viscosity-increasing agent that is also capable of increasing the suspending capacity of a fluid is to use a viscoelastic surfactant. As used herein, the term “viscoelastic surfactant” refers to a surfactant that imparts or is capable of imparting viscoelastic behavior to a fluid due, at least in part, to the association of surfactant molecules to form viscosifying micelles. These viscoelastic surfactants may be cationic, anionic, or amphoteric in nature. The viscoelastic surfactants can comprise any number of different compounds, including methyl ester sulfonates (e.g., as described in U.S. patent application Ser. Nos. 11/058,660, 11/058,475, 11/058,612, and 11/058,611, filed Feb. 15, 2005, the relevant disclosures of which are incorporated herein by reference), hydrolyzed keratin (e.g., as described in U.S. Pat. No. 6,547,871, the relevant disclosure of which is incorporated herein by reference), sulfosuccinates, taurates, amine oxides, ethoxylated amides, alkoxylated fatty acids, alkoxylated alcohols (e.g., lauryl alcohol ethoxylate, ethoxylated nonyl phenol), ethoxylated fatty amines some of which are described in U.S. Pat. Nos. 4,061,580, 4,324,669, and 4,215,001 the relevant disclosures of which are incorporated herein by reference, ethoxylated alkyl amines (e.g., cocoalkylamine ethoxylate), betaines, modified betaines, alkylamidobetaines (e.g., cocoamidopropyl betaine), quaternary ammonium compounds (e.g., trimethyltallowammonium chloride, trimethylcocoammonium chloride), derivatives thereof, and combinations thereof.
Suitable viscoelastic surfactants may comprise mixtures of several different compounds, including but not limited to: mixtures of an ammonium salt of an alkyl ether sulfate, a cocoamidopropyl betaine surfactant, a cocoamidopropyl dimethylamine oxide surfactant, sodium chloride, and water; mixtures of an ammonium salt of an alkyl ether sulfate surfactant, a cocoamidopropyl hydroxysultaine surfactant, a cocoamidopropyl dimethylamine oxide surfactant, sodium chloride, and water; mixtures of an ethoxylated alcohol ether sulfate surfactant, an alkyl or alkene amidopropyl betaine surfactant, and an alkyl or alkene dimethylamine oxide surfactant; aqueous solutions of an alpha-olefinic sulfonate surfactant and a betaine surfactant; and combinations thereof. Examples of suitable mixtures of an ethoxylated alcohol ether sulfate surfactant, an alkyl or alkene amidopropyl betaine surfactant, and an alkyl or alkene dimethylamine oxide surfactant are described in U.S. Pat. No. 6,063,738, the relevant disclosure of which is incorporated herein by reference. Examples of suitable aqueous solutions of an alpha-olefinic sulfonate surfactant and a betaine surfactant are described in U.S. Pat. No. 5,879,699, the relevant disclosure of which is incorporated herein by reference.
Examples of commercially-available viscoelastic surfactants suitable for use in the present invention can include, but are not limited to, Mirataine BET-O 30™ (an oleamidopropyl betaine surfactant available from Rhodia Inc., Cranbury, N.J.), Aromox APA-T (amine oxide surfactant available from Akzo Nobel Chemicals, Chicago, Ill.), Ethoquad O/12 PG™ (a fatty amine ethoxylate quat surfactant available from Akzo Nobel Chemicals, Chicago, Ill.), Ethomeen T/12™ (a fatty amine ethoxylate surfactant available from Akzo Nobel Chemicals, Chicago, Ill.), Ethomeen S/12™ fatty amine ethoxylate surfactant available from Akzo Nobel Chemicals, Chicago, Ill.), and Rewoteric AM TEG™ tallow dihydroxyethyl betaine amphoteric surfactant available from Degussa Corp., Parsippany, N.J.). See, for example, U.S. Pat. No. 7,727,935, issued Jun. 1, 2010, incorporated herein by reference.
Viscous Fluid Damage to Permeability
In the fracturing of conventional reservoirs having relatively high permeability, viscous fluids used for carrying a proppant can damage the permeability of the proppant pack or the subterranean formation near the fracture. For example, a fracturing fluid may be or include a gel that is deposited in the fracture. The fluid may include surfactants that leave unbroken micelles in the fracture or change the wettability of the formation in the region of the fracture. The higher the viscosity of the fracturing fluid, the more likely it is to damage the permeability of a proppant pack or formation.
Breakers are utilized in many treatments to mitigate fluid damage in the fracture. However, breakers and other treatments are subject to variability of results, they add expense and complication to a fracture treatment, and in all cases still leave at least some fluid damage in the fracture.
In addition, the chemistry of fracturing gels, including the crosslinking of gels, creates complications when designing fracture treatments for a broad range of temperatures. After a fracture treatment, fracturing fluid that flows back to the surface must be disposed of, and the more fluid that is utilized in the treatment the greater the disposal risk and expense. Accordingly, in the fracturing of conventional reservoirs where the matrix permeability allows the fracturing fluid to enter the matrix of the formation rock, it is often desirable to minimize fluid loss into the formation.
Other Uses of Polymers in Well Fluids, for Example, as Friction Reducer
There are other uses for a polymers in a well fluid. For example, a polymer may be used as a friction reducer.
During the drilling, completion and stimulation of subterranean wells, well fluids are often pumped through tubular structures (e.g., pipes, coiled tubing, etc.). A considerable amount of energy may be lost due to turbulence in the treatment fluid. Because of these energy losses, additional horsepower may be necessary to achieve the desired treatment. To reduce these energy losses, certain polymers (referred to herein as “friction-reducing polymers”) have been included in these treatment fluids.
For example, one type of hydraulic fracturing treatment that may utilize friction-reducing polymers is commonly referred to as “high-rate water fracturing” or “slick water fracturing.” As will be appreciated by those of ordinary skill in the art, fracturing fluids used in these high-rate water-fracturing systems are generally not gels. As such, in high-rate water fracturing, fluid velocity rather than viscosity is relied on for proppant transport. Additionally, while fluids used in high-rate water fracturing may contain a friction-reducing polymer, the friction-reducing polymer is generally included in the fracturing fluid in an amount sufficient to provide the desired friction reduction without gel formation. Gel formation would cause an undesirable increase in fluid viscosity that would result in increased pumping horsepower requirements. More preferably, a friction-reducing polymer is used in an amount that is sufficient to provide the desired friction reduction without appreciably viscosifying the fluid and usually without a crosslinker. As a result, the fracturing fluids used in these high-rate water-fracturing operations generally have a lower viscosity than conventional fracturing fluids. Typically, a well fluid in which a polymer is used as a friction reducer has a viscosity in the range of about 0.7 cP to about about 10 cP. For the purposes of this disclosure, viscosities are measured at room temperature using a FANN® Model 35 viscometer at 300 rpm with a ⅕ spring.
An example of a stimulation operation that may utilize friction reducing polymers is hydraulic fracturing. Hydraulic fracturing is a process commonly used to increase the flow of desirable fluids, such as oil and gas, from a portion of a subterranean formation. In hydraulic fracturing, a fracturing fluid may be introduced into the subterranean formation at or above a pressure sufficient to create or enhance one or more fractures in the formation. Enhancing a fracture may include enlarging a pre-existing fracture in the formation. To reduce frictional energy losses within the fracturing fluid, friction-reducing polymers may be included in the fracturing fluid. One type of hydraulic fracturing treatment that may utilize friction-reducing polymers is commonly referred to as “high rate water fracturing” or “slick water fracturing.” As will be appreciated by those of ordinary skill in the art, fracturing fluids used in these high rate water-fracturing systems are generally not gels. As such, in high rate water fracturing, velocity rather than the fluid viscosity is relied on for proppant transport. Additionally, while fluids used in high rate water fracturing may contain a friction-reducing polymer, the friction-reducing polymer is generally included in the fracturing fluid in an amount sufficient to provide the desired friction reduction without gel formation. Gel formation would cause an undesirable increase in fluid viscosity that would, in return, result in increased horsepower requirements.
Suitable friction reducing polymers should reduce energy losses due to turbulence within the treatment fluid. Those of ordinary skill in the art will appreciate that the friction reducing polymer(s) included in the treatment fluid should have a molecular weight sufficient to provide a desired level of friction reduction. In general, polymers having higher molecular weights may be needed to provide a desirable level of friction reduction. By way of example, the average molecular weight of suitable friction reducing polymers may be at least about 2,500,000, as determined using intrinsic viscosities. In certain embodiments, the average molecular weight of suitable friction reducing polymers may be in the range of from about 7,500,000 to about 20,000,000. Those of ordinary skill in the art will recognize that friction-reducing polymers having molecular weights outside the listed range may still provide some degree of friction reduction. Typically, friction-reducing polymers are linear and flexible, for example, having a persistence length <10 nm.
A wide variety of friction reducing polymers may be suitable for use with the present invention. In certain embodiments, the friction-reducing polymer may be a synthetic polymer. Additionally, for example, the friction-reducing polymer may be an anionic polymer or a cationic polymer, in accordance with embodiments of the present invention.
By way of example, suitable synthetic polymers may comprise any of a variety of monomeric units, including acrylamide, acrylic acid, 2-acrylamido-2-methylpropane sulfonic acid, N,N-dimethylacrylamide, vinyl sulfonic acid, N-vinyl acetamide, N-vinyl formamide, itaconic acid, methacrylic acid, acrylic acid esters, methacrylic acid esters, quaternized aminoalkyl acrylate, such as a copolymer of acrylamide and dimethylaminoethyl acrylate quaternized with benzyl chloride, and mixtures thereof.
Examples of suitable friction reducing polymers are described in U.S. Pat. No. 6,784,141, U.S. patent application Ser. Nos. 11/156,356, 11/300,614, and 11/300,615, the disclosure of which is incorporated herein by reference. Combinations of suitable friction reducing polymers may also be suitable for use.
One example of a suitable anionic friction-reducing polymer is a polymer comprising acrylamide and acrylic acid. The acrylamide and acrylic acid may be present in the polymer in any suitable concentration. An example of a suitable anionic friction reducing polymer may comprise acrylamide in an amount in the range of from about 5% to about 95% and acrylic acid in an amount in the range of from about 5% to about 95%. Another example of a suitable anionic friction-reducing polymer may comprise acrylamide in an amount in the range of from about 60% to about 90% by weight and acrylic acid in an amount in the range of from about 10% to about 40% by weight. Another example of a suitable anionic friction-reducing polymer may comprise acrylamide in an amount in the range of from about 80% to about 90% by weight and acrylic acid in an amount in the range of from about 10% to about 20% by weight. Yet another example of a suitable anionic friction-reducing polymer may comprise acrylamide in an amount of about 85% by weight and acrylic acid in an amount of about 15% by weight. As previously mentioned, one or more additional monomers may be included in the anionic friction reducing polymer comprising acrylamide and acrylic acid. By way of example, the additional monomer(s) may be present in the anionic friction-reducing polymer in an amount up to about 20% by weight of the polymer.
Suitable friction-reducing polymers may be in an acid form or in a salt form. As will be appreciated, a variety of salts may be prepared, for example, by neutralizing the acid form of the acrylic acid monomer or the 2-acrylamido-2-methylpropane sulfonic acid monomer. In addition, the acid form of the polymer may be neutralized by ions present in the treatment fluid. As used herein, the term “polymer” is intended to refer to the acid form of the friction-reducing polymer, as well as its various salts.
As will be appreciated, the friction-reducing polymers suitable for use in the present technique may be prepared by any suitable technique. For example, the anionic friction-reducing polymer comprising acrylamide and acrylic acid may be prepared through polymerization of acrylamide and acrylic acid or through hydrolysis of polyacrylamide (e.g., partially hydrolyzed polyacrylamide). See, for example, U.S. Pat. Nos. 7,846,878 and 7,806,185, which are incorporated by reference.
Spacer Fluids
A spacer fluid is a fluid used to physically separate one special-purpose fluid from another. Special-purpose fluids are typically prone to contamination, so a spacer fluid compatible with each is used between the two. A spacer fluid is used when changing well fluids used in a well. For example, a spacer fluid is used to change from a drilling fluid during drilling a well to a cement slurry during cementing operations in the well. In case of an oil-based drilling fluid, it should be kept separate from a water-based cementing fluid. In changing to the latter operation, a chemically treated water-based spacer fluid is usually used to separate the drilling fluid from the cement slurry. Another example is using a spacer fluid to separate two different treatment fluids.
Well Fluid Additives
A well fluid can contain additives that are commonly used in oil field applications, as known to those skilled in the art. These include, but are not necessarily limited to, inorganic water-soluble salts, breaker aids, surfactants, oxygen scavengers, alcohols, scale inhibitors, corrosion inhibitors, fluid-loss additives, oxidizers, water control agents (such as relative permeability modifiers), consolidating agents, proppant flowback control agents, conductivity enhancing agents, and bactericides.
Variations in Well Fluids Over Time
Unless the specific context otherwise requires, a “well fluid” refers to the specific properties and composition of a fluid at the time the fluid is being introduced into a well. In addition, it should be understood that, during the course of a well operation such as drilling, cementing, completion, or intervention, or during a specific treatment such as fluid-loss control, hydraulic fracturing, or a matrix treatment, the specific properties and composition of a type of well fluid can be varied or several different types of well fluids can be used. For example, the compositions can be varied to adjust viscosity or elasticity of the well fluids to accommodate changes in the concentrations of proppant to be carried down to the subterranean formation from initial packing of the fracture to tail-end packing. It can also be desirable to accommodate expected changes in temperatures encountered by the well fluids during the course of the treatment. By way of another example, it can be desirable to accommodate the longer duration that the first treatment fluid may need to maintain viscosity before breaking compared to the shorter duration that a later-introduced treatment fluid may need to maintain viscosity before breaking. Changes in concentration of the proppant, viscosity-increasing agent, or other additives in the various treatment fluids of a treatment operation can be made in stepped changes of concentrations or ramped changes of concentrations.
Continuum Mechanics and Rheology
One of the purposes of identifying the physical state of a substance and measuring viscosity or other physical characteristics of a fluid is to establish whether it is pumpable. In the context of oil and gas production, the pumpability of a fluid is with particular reference to the ranges of physical conditions that may be encountered at a wellhead and with the types and sizes of pumps available to be used for pumping fluids into a well. Another purpose is to determine what the physical state of the substance and its physical properties will be during pumping through a wellbore and under other downhole conditions in the well, including over time and changing temperatures, pressures, and shear rates. For example, in some applications, a well fluid forms or becomes a higher viscosity fluid or gel under downhole conditions that later is “broken” back to a lower viscosity fluid.
Continuum mechanics is a branch of mechanics that deals with the analysis of the kinematics and the mechanical behavior of materials modeled as a continuous mass on a large scale rather than as distinct particles. Fluid mechanics is a branch of continuum mechanics that studies the physics of continuous materials that take the shape of their container. Rheology is the study of the flow of matter: primarily in the liquid state, but also as “soft solids” or solids under conditions in which they respond with plastic flow rather than deforming elastically in response to an applied force. It applies to substances that have a complex structure, such as fluid suspensions, gels, etc. The flow of such substances cannot be fully characterized by a single value of viscosity, which varies with temperature, pressure, and other factors. For example, ketchup can have its viscosity reduced by shaking (or other forms of mechanical agitation) but water cannot.
Physical States (Phases)
The common physical states of matter include solid (fixed shape and volume), liquid (fixed volume and shaped by a container), and gas (dispersing in a container). Distinctions among these physical states are based on differences in intermolecular attractions. Solid is the state in which intermolecular attractions keep the molecules in fixed spatial relationships. Liquid is the state in which intermolecular attractions keep molecules in proximity (low tendency to disperse), but do not keep the molecules in fixed relationships. Gas is that state in which the molecules are comparatively separated and intermolecular attractions have relatively little effect on their respective motions (high tendency to disperse).
In addition, as used herein, a solid includes a plastic material, that is, a material that has plasticity. Plasticity describes the deformation of a material undergoing non-reversible changes of shape in response to applied forces.
As used herein, “phase” is used in the same sense as physical state, regardless of geometric extent of the phase or size of a particle.
The physical state of a substance is based on thermodynamics. Thermodynamics is the science of energy conversion involving heat, mechanical work, and other forms of energy. It studies and interrelates variables, such as temperature, volume, pressure, and friction, which describe physical, thermodynamic systems.
As used herein, if not otherwise specifically stated, the physical state (phase) or other physical properties of a material are determined at a temperature of 77° F. (25° C.) and a pressure of 1 atmosphere (Standard Laboratory Conditions) and no applied deformation force or shear (that is, not other such force than that of natural gravity).
Particles
As used herein, a “particle” refers a body having a finite mass and sufficient cohesion such that it can be considered as an entity but having relatively small dimensions. As used herein, a particle can be of any size ranging from molecular scale particles to macroscopic particles, depending on context. A particle can be in any physical state. For example, a particle of a substance in a solid state can be as small as a few molecules on the scale of nanometers up to a large particle on the scale of a few millimeters, such as large grains of sand. Similarly, a particle of a substance in a liquid state can be as small as a few molecules on the scale of nanometers or a large drop on the scale of a few millimeters. A particle of a substance in a gas state is a single atom or molecule that is separated from other atoms or molecules such that intermolecular attractions have relatively little effect on their respective motions.
Particulate
As used herein, “particulate” or “particulate material” refers to matter in the physical form of distinct particles. A particulate is a grouping of particles based on common characteristics, including chemical composition and particle size range, particle size distribution, or median particle size. As used herein, a particulate is a grouping of particles having similar chemical composition and particle size ranges anywhere in the range of about 1 micrometer (e.g., microscopic clay or silt particles) to about 3 millimeters (e.g., large grains of sand).
A particulate will have a particle size distribution (“PSD”). As used herein, “the size” of a particulate can be determined by methods known to persons skilled in the art.
Solid Particulate
A particulate can be of solid or liquid particles. As used herein, however, unless the context otherwise requires, particulate refers to a solid particulate. Of course, a solid particulate is a particulate of particles that are in the solid physical state, that is, the constituent atoms, ions, or molecules are sufficiently restricted in their relative movement to result in a fixed shape for each of the particles.
One way to measure the approximate particle size distribution of a solid particulate is with graded screens. A solid particulate material will pass through some specific mesh (that is, have a maximum size; larger pieces will not fit through this mesh) but will be retained by some specific tighter mesh (that is, a minimum size; pieces smaller than this will pass through the mesh). This type of description establishes a range of particle sizes. A “+” before the mesh size indicates the particles are retained by the sieve, while a “−” before the mesh size indicates the particles pass through the sieve. For example, −70/+140 means that 90% or more of the particles will have mesh sizes between the two values.
Particulate materials are sometimes described by a single mesh size, for example, 100 U.S. Standard mesh. If not otherwise stated, a reference to a single particle size means about the mid-point of the industry accepted mesh size range for the particulate.
Particulate smaller than about 400 U.S. Standard Mesh is usually measured or separated according to other methods because small forces such as electrostatic forces can interfere with separating tiny particulate sizes using a wire mesh.
Udden-Wentworth Scale for Particulate Sediments
The most commonly-used grade scale for classifying the diameters of sediments in geology is the Udden-Wentworth scale. According to this scale, a solid particulate having particles smaller than 2 mm in diameter is classified as sand, silt, or clay. Sand is a detrital grain between 2 mm (equivalent to 2,000 micrometers) and 0.0625 mm (equivalent to 62.5 micrometers) in diameter. (Sand is also a term sometimes used to refer to quartz grains or for sandstone.) Silt refers to particulate between 74 micrometers (equivalent to about −200 U.S. Standard mesh) and about 2 micrometers. Clay is a particulate smaller than 0.0039 mm (equivalent to 3.9 μm).
Dispersions
A substance can have more than one phase. A dispersion is a system in which particles of a substance of one state are dispersed in another substance of a different composition or physical state. In addition, phases can be nested. If a substance has more than one phase, the most external phase is referred to as the continuous phase of the substance as a whole, regardless of the number of different internal phases or nested phases.
A dispersion can be classified a number of different ways, including based on the size of the dispersed particles, the uniformity or lack of uniformity of the dispersion, whether or not precipitation occurs, and the presence of Brownian motion. For example, a dispersion can be considered to be homogeneous or heterogeneous based on being a solution or not, and if not a solution, based on the size of the dispersed particles (which can refer to droplet size in the case of a dispersed liquid phase).
Classification of Dispersions: Homogeneous and Heterogeneous
A dispersion is considered to be homogeneous if the dispersed particles are dissolved in solution or the particles are less than about 1 nanometer in size.
A solution is a special type of homogeneous mixture. Solvation is the process of attraction and association of molecules of a solvent with molecules or ions of a solute. A solution is homogeneous because the ratio of solute to solvent is the same throughout the solution and because solute will never settle out of solution, even under powerful centrifugation. This is due to intermolecular attraction between the solvent and the solute. An aqueous solution, for example, saltwater, is a homogenous solution in which water is the solvent and salt is the solute.
Even if not dissolved, a dispersion is considered to be homogeneous if the dispersed particles are less than about 1 nanometer in size.
A dispersion is considered to be heterogeneous if the dispersed particles are not dissolved or are greater than about 1 nanometer in size. (For reference, the diameter of a molecule of toluene is about 1 nm).
Heterogeneous dispersions can have gas, liquid, or solid as an external phase. An example of a suspension of solid particulate dispersed in a gas phase would be an aerosol, such as smoke. In case the dispersed-phase particles are liquid in an external phase that is another liquid, this kind of heterogeneous dispersion is more particularly referred to as an emulsion. Suspensions and emulsions are commonly used as well fluids.
Classification of Heterogeneous Dispersions: Colloids and Suspensions
Heterogeneous dispersions can be further classified based on the dispersed particle size.
A heterogeneous dispersion is a “colloid” where the dispersed particles range up to about 1 micrometer (1,000 nanometers) in size. Typically, the dispersed particles of a colloid have a diameter of between about 5 to about 200 nanometers. Such particles are normally invisible to an optical microscope, though their presence can be confirmed with the use of an ultramicroscope or an electron microscope. In the cases where the external phase of a dispersion is a liquid, for a colloidal fluid the dispersed particles are so small that they do not settle.
A heterogeneous dispersion is a “suspension” where the dispersed particles are larger than about 1 micrometer. Such particles can be seen with a microscope, or if larger than about 100 micrometers (0.1 mm), with the unaided human eye. Unlike colloids, however, the dispersed particles of a suspension in a liquid external phase may eventually separate on standing, e.g., settle in cases where the particles have a higher density than the liquid phase. Suspensions having a liquid external phase are essentially unstable from a thermodynamic point of view; however, they can be kinetically stable over a long period depending on temperature and other conditions.
Gel and Deformation
The substance of a gel is a colloidal dispersion. A gel is formed by a network of interconnected molecules, such as of a crosslinked polymer or of micelles, which at the molecular level are attracted to molecules in liquid form. The network gives a gel phase its structure (apparent yield point) and contributes to stickiness (tack). By weight, the substance of gels is mostly liquid, yet they behave like solids due to the three-dimensional network with the liquid. At the molecular level, a gel is a dispersion in which the network of molecules is continuous and the liquid is discontinuous.
A gel is a semi-solid, jelly-like state or phase that can have properties ranging from soft and weak to hard and tough. Shearing stresses below a certain finite value fail to produce permanent deformation. The minimum shear stress which will produce permanent deformation is known as the shear or gel strength of the gel.
A gel is considered to be a single phase because the intermolecular attractions between the molecules of the network and the molecules of the liquid contribute to its semi-solid, jelly-like properties.
Fluid and Apparent Viscosity
The substance of a fluid can be a single chemical substance or a dispersion. In general, a fluid is an amorphous substance that is or has a continuous phase of particles that are smaller than about 1 micrometer that tends to flow and to conform to the outline of its container.
Examples of fluids are gases and liquids. A gas (in the sense of a physical state) refers to an amorphous substance that has a high tendency to disperse (at the molecular level) and a relatively high compressibility. A liquid refers to an amorphous substance that has little tendency to disperse (at the molecular level) and relatively high incompressibility. The tendency to disperse is related to Intermolecular Forces (also known as van der Waal's Forces). (A continuous mass of a particulate, e.g., a powder or sand, can tend to flow as a fluid depending on many factors such as particle size distribution, particle shape distribution, the proportion and nature of any wetting liquid or other surface coating on the particles, and many other variables; nevertheless, as used herein, a fluid does not refer to a continuous mass of particulate. The sizes of the solid particles of a mass of a particulate are too large to be appreciably affected by the range of Intermolecular Forces.)
Viscosity is the resistance of a fluid to flow. In everyday terms, viscosity is “thickness” or “internal friction.” Thus, pure water is “thin,” having a relatively low viscosity whereas honey is “thick,” having a relatively higher viscosity. Put simply, the less viscous the fluid is, the greater its ease of movement (fluidity). More precisely, viscosity is defined as the ratio of shear stress to shear rate.
A Newtonian fluid (named after Isaac Newton) is a fluid for which stress versus strain rate curve is linear and passes through the origin. The constant of proportionality is known as the viscosity. Examples of Newtonian fluids include water and most gases. Newton's law of viscosity is an approximation that holds for some substances but not others.
Non-Newtonian fluids exhibit a more complicated relationship between shear stress and velocity gradient (i.e., shear rate) than simple linearity. Thus, there exist a number of forms of non-Newtonian fluids. Shear thickening fluids have an apparent viscosity that increases with the rate of shear. Shear thinning fluids have a viscosity that decreases with the rate of shear. Thixotropic fluids become less viscous over time when shaken, agitated, or otherwise stressed. Rheopectic fluids become more viscous over time when shaken, agitated, or otherwise stressed. A Bingham plastic is a material that behaves as a solid at low stresses but flows as a viscous fluid at high stresses.
Most well fluids are non-Newtonian fluids. Accordingly, the apparent viscosity of a fluid applies only under a particular set of conditions including shear stress versus shear rate, which must be specified or understood from the context. In the oilfield and as used herein, unless the context otherwise requires it is understood that a reference to viscosity is actually a reference to an apparent viscosity. Apparent viscosity is commonly expressed in units of centipoise (“cP”).
Like other physical properties, the viscosity of a Newtonian fluid or the apparent viscosity of a non-Newtonian fluid is highly dependent on the physical conditions, primarily temperature and pressure. Accordingly, unless otherwise stated, the viscosity or apparent viscosity of a fluid is measured under Standard Laboratory Conditions.
There are numerous ways of measuring and modeling viscous properties, and new developments continue to be made. The methods depend on the type of fluid for which viscosity is being measured. A typical method for quality assurance or quality control (QA/QC) purposes uses a couette device, such as a Fann Model 50 viscometer, that measures viscosity as a function of time, temperature, and shear rate. The viscosity-measuring instrument can be calibrated using standard viscosity silicone oils or other standard viscosity fluids.
Due to the geometry of most common viscosity-measuring devices, however, solid particulate, such as proppant or gravel used in certain well treatments, would interfere with the measurement on some types of measuring devices. Therefore, the viscosity of a fluid containing such solid particulate is usually inferred and estimated by measuring the viscosity of a test fluid that is similar to the fracturing fluid without any proppant included. However, as suspended particles (which can be solid, gel, liquid, or bubbles of gas) usually affect the viscosity of a fluid, the actual viscosity of a suspension is usually somewhat different from that of the continuous phase.
Another example of a method of measuring the viscosity of certain fluids that have suspended proppant uses a Proppant Transport Measuring Device (“PTMD”), which is disclosed in U.S. Pat. No. 7,392,842, issued Jul. 1, 2008 and in SPE 115298. The PTMD instrument is preferably calibrated against a more conventional instrument, for example, against a Fann Model 50 viscometer.
Other examples of methods of measuring the viscosity of a fluid include: (1) Tonmukayakul. N. Bryant, J. E. Talbot, M. S. and Morris, J. F., “Dynamic and steady shear properties of reversible cross-linked guar solution and their effects on particle settling behavior”, The XVth International Congress on Rheology, Monterey, Calif., 3-8 Aug. 2008. American Institute of Physic Conference Proceedings 1027 ISBN:978-0-7354-0549-3; (2) Tonmukayakul N. Bryant, J. E. and Morris, J. F., “Experimental investigation of the sedimentation behavior of concentrated suspension in non-Newtonian fluids under simple shear flows”, 82nd Annual Meeting, The Society of Rheology, Santa Fe, N. Mex., Oct. 24-28, 2010; (3) Tonmukayakul N. and Morris, J. F., “Sedimentation of Particles in Viscoelastic Fluids Under Imposed Shear Conditions,” J. Rheol, 2011 (in press); (4) Tonmukayakul, N., Morris, J. E., Prud'homme, R. E. “Method for estimating proppant transport and suspendability of viscoelastic liquids” US application filed on May 17, 2010, U.S. application Ser. No. 12/722,493 and it was filed on Mar. 11, 2010; and (5) Tonmukayakul N. and Morris, J. F., “Spreading Front and Particles Alignment in Viscoelastic Fluids,” Physical Review E, 2011 (in press).
Foams
A foam is fluid having a liquid external phase that includes a dispersion of undissolved gas bubbles that foam the liquid, usually with the aid of a chemical (a foaming agent) in the liquid phase to achieve stability.
Any suitable gas may be used for foaming, including nitrogen, carbon dioxide, air, or methane. A foamed treatment fluid may be desirable to, among other things, reduce the amount of fluid that is required in a water sensitive subterranean formation, to reduce fluid loss in the formation, and/or to provide enhanced proppant suspension. In examples of such embodiments, the gas may be present in the range of from about 5% to about 98% by volume of the treatment fluid, and more preferably in the range of from about 20% to about 80% by volume of the treatment fluid. The amount of gas to incorporate in the fluid may be affected by many factors including the viscosity of the fluid and the bottom hole temperatures and pressures involved in a particular application. One of ordinary skill in the art, with the benefit of this disclosure, will recognize how much gas, if any, to incorporate into a foamed treatment fluid.
In those embodiments where it is desirable to foam the treatment fluids of the present invention, surfactants such as HY-CLEAN (HC-2) surface-active suspending agent or AQF-2 additive, both commercially available from Halliburton Energy Services, Inc., of Duncan, Okla., may be used. Additional examples of foaming agents that may be used to foam and stabilize the treatment fluids of this invention include, but are not limited to, betaines, amine oxides, methyl ester sulfonates, alkylamidobetaines such as cocoamidopropyl betaine, alpha-olefin sulfonate, trimethyltallowammonium chloride, C8 to C22 alkylethoxylate sulfate and trimethylcocoammonium chloride. Other suitable foaming agents and foam stabilizing agents may be included as well, which will be known to those skilled in the art with the benefit of this disclosure.
Emulsions
An emulsion is a fluid including a dispersion of immiscible liquid particles in an external liquid phase. In addition, the proportion of the external and internal phases is above the solubility of either in the other. A chemical (an emulsifier or emulsifying agent) can be included to reduce the interfacial tension between the two immiscible liquids to help with stability against coalescing of the internal liquid phase.
An emulsion can be an oil-in-water (o/w) type or water-in-oil (w/o) type. A water-in-oil emulsion is sometimes referred to as an invert emulsion. In the context of an emulsion, the “water” phase refers to water or an aqueous solution and the “oil” phase refers to any non-polar organic liquid, such as petroleum, kerosene, or synthetic oil.
It should be understood that multiple emulsions are possible, which are sometimes referred to as nested emulsions. Multiple emulsions are complex polydispersed systems where both oil-in-water and water-in-oil emulsions exist simultaneously in the fluid, wherein the oil-in-water emulsion is stabilized by a lipophilic surfactant and the water-in-oil emulsion is stabilized by a hydrophilic surfactant. These include water-in-oil-in-water (w/o/w) and oil-in-water-in-oil (o/w/o) type multiple emulsions. Even more complex polydispersed systems are possible. Multiple emulsions can be formed, for example, by dispersing a water-in-oil emulsion in water or an aqueous solution, or by dispersing an oil-in-water emulsion in oil.
Classification of Fluids or Gels: Water-Based or Oil-Based
As used herein, “water-based” regarding a fluid or gel means that water or an aqueous solution is the dominant material by weight of the continuous phase of the substance. In contrast, “oil-based” means that oil is the dominant material by weight of the continuous phase of the substance as a whole.